Novel Steam Reformer Based Hydrogen Plant Scheme for Enhanced Carbon Dioxide Recovery

ABSTRACT

A novel steam reformer unit design, a novel hydrogen PSA unit design, a novel hydrogen/nitrogen enrichment unit design, and novel processing scheme application are presented. The result of these innovations results in re-allocating most of the total hydrogen plant CO2 emissions load to high pressure syngas stream exiting the water gas shift reactor while minimizing the CO2 emissions load from the reformer furnace flue gas. As compared to the conventional 60/40 split of total CO2 emissions in syngas/flue gas streams for steam reformer based conventional hydrogen plant designs, the present invention results in 85/15 or better CO2 split. This will permit about 85% or better of the total CO2 emissions load to be captured from the syngas stream, using the conventional, well proven and cost effective amine scrubbing technology. Such 85% or better CO2 capture is much greater than the 55% to 60% maximum possible using conventional steam reformer based hydrogen plant technology. As CO2 recovery from high pressure syngas stream is much easier and cost effective as compared to that from low pressure reformer furnace flue gases, a major cost benefit for equivalent CO2 recovery results with the present invention.

This application claims the benefit of U.S. Provisional Application No.61/088,420, filed Aug. 13, 2008, U.S. Provisional Application No.61/093,746 filed Sep. 3, 2008, and U.S. Provisional Application No.61/108,273, filed Oct. 24, 2008, the entire contents of which areincorporated herein by reference.

FIELD OF THE INVENTION

This invention relates to novel steam reformer unit design, a novelhydrogen PSA unit design, a novel hydrogen/nitrogen enrichment unitdesign, and a novel processing scheme application.

BACKGROUND

The production of hydrogen by the steam reforming of hydrocarbons iswell known. In the basic process, a hydrocarbon, or a mixture ofhydrocarbons, is initially treated to remove, or convert and thenremove, trace contaminants, such as sulfur and olefins, which wouldadversely affect the reformer and the down stream water gas shift unitcatalyst. Natural gas containing predominantly methane is a preferredstarting material since it has a higher proportion of hydrogen thanother hydrocarbons. However, light hydrocarbons or refinery off gasescontaining hydrocarbons, or refinery streams such as LPG, naphthahydrocarbons or others readily available light feeds might be utilizedas well.

The pretreated hydrocarbon feed stream is typically at a pressure ofabout 200 to 400 psig, and combined with high pressure steam, which isat a higher than the feed stream pressure, before entering the reformerfurnace. The amount of steam added is much in excess of thestoichiometric amount. The reformer itself conventionally contains tubespacked with catalyst through which the steam/hydrocarbon mixture passes.An elevated temperature, e.g. about 1580° F., or 860° C., is maintainedto drive the endothermic reaction.

The effluent from the reformer furnace is principally hydrogen, carbonmonoxide, carbon dioxide, water vapor, and methane in proportion closeto equilibrium amounts at the furnace temperature and pressure. Theeffluent is conventionally introduced into a one- or two-stage water gasshift reactor to form additional hydrogen and carbon dioxide. The shiftreactor converts the carbon monoxide to carbon dioxide by reaction withwater vapor, which generates additional Hydrogen. This reaction isendothermic. The combination of steam reformer and water gas shiftconverter is well known to those of ordinary skill in the art.

If CO2 capture from the high pressure syngas stream exiting the watergas shift unit is desired, the shift converter effluent, which compriseshydrogen, carbon dioxide and water with minor quantities of methane andcarbon monoxide is introduced into a conventional absorption unit forcarbon dioxide removal. Such a unit operates on the well-known aminewash or Benfield processes wherein carbon dioxide is removed from theeffluent by dissolution in an absorbent solution, i.e. an amine solutionor potassium carbonate solution, respectively. Conventionally, suchunits can remove up to 99 percent or higher of the carbon dioxide in theshift converter effluent. The effluent from the carbon dioxideabsorption unit is introduced into a pressure swing adsorption (PSA)unit. PSA is a well-known process for separating essentially purehydrogen from the mixture-of gases as a result of the difference in thedegree of adsorption among them on a particulate adsorbent retained in astationary bed.

Conventionally, the remainder of the PSA unit feed components, afterrecovery of pure hydrogen product, which comprises carbon monoxide, thehydrocarbon, i.e. methane, hydrogen and carbon dioxide, is returned tothe steam reformer furnace and combusted to obtain energy for usetherein

To practice CO2 emissions capture from such hydrogen plants, one mustconsider total emissions resulting from the plant, which includes CO2recovery from reformer furnace flue gas as well.

The CO2 emissions from a steam reformer based conventional hydrogenplant originate from the reformer furnace flue gas. The root source ofthis total CO2 in the furnace flue gas results from two sources:

-   -   (a) the reaction within the reformer tubes and shift; and    -   (b) the combustion of fuel in reformer furnace.    -   (c)        Each source contributes between about 40 and about 60% of the        total CO2 emitted through the reformer furnace flue gas. For CO2        capture, conventional schemes employed consist of:    -   (a) removal of CO2, only from the high pressure syngas stream        exit shift unit;    -   (b) removal of CO2, only from the reformer furnace flue gas; and    -   (c) removal of CO2 via both (a) and (b) above.    -   (d)        Option (a) permits about 50 to about 60% of total CO2 emissions        capture. Option (b) permits about 90% of total CO2 emissions        capture. Option (c) permits about 95% of the total CO2 emissions        capture. Option (a) permits only partial capture at reasonable        cost, Option (b) is considered the most expensive of the three        options, capital and utility requirements wise. Option (c) is        also expensive, utility intensive and quite elaborate.

Therefore, it is very desirable and cost effective to have a H2 plantdesign that results in between about 85% and about 95%+ of total CO2capture, solely from the high pressure syngas stream exit water gasshift reactor.

SUMMARY

The present invention is a novel steam reformer design and method usingthe same. This method includes a variety of steps of which the first isto provide a first gas mixture This first gas mixture may comprisenatural gas containing mostly methane, light hydrocarbons, refinery offgases containing hydrocarbons, refinery streams such as LPG, naphthahydrocarbons or other readily available light feeds. Step two involvesintroducing said first gas mixture into either a pre-reformer followedby a primary reformer, or directly into a primary reformer, therebygenerating a second gas mixture comprising hydrogen, carbon monoxide,carbon dioxide. The novelty here is in the design and operatingparameters of the primary reformer. The third step of the methodincludes introducing said second gas mixture into at least oneisothermal shift reactor, or a combination of a high followed by a lowtemperature shift reactor, or a medium temperature shift reactor,thereby generating a third gas mixture. Step four includes introducingsaid third gas mixture into an amine wash, wherein said third gas isseparated into a fourth gas mixture and a carbon dioxide enrichedstream. The fifth step includes introducing said fourth gas mixture intoa standard hydrogen PSA, wherein said fourth gas is separated into ahydrogen enriched stream and a PSA purge gas stream. In the final step,the reformer furnace uses the PSA purge gas as fuel with thesupplemental fuel or remainder of the fuel for the reformer furnacebeing natural gas or a portion of the feed hydrocarbon stream, or anyother external fuel. By virtue of the novel reformer, the syngas/fluegas CO2 distribution is higher than the conventional design.

In one embodiment of the present invention, the novel steam reformerdesign along with a novel hydrogen PSA design that is lower cost isused. Additionally, this embodiment is self-sufficient in reformerfurnace fuel requirements and therefore does not require any import ofsupplemental fuel.

This embodiment is the same with regard to steps one to four above butdiffers in the remaining steps. More specifically, the fifth step ofthis embodiment includes introducing said fourth gas mixture into eithera standard recovery or a special low recovery PSA, wherein said fourthgas is separated into a hydrogen enriched stream and a PSA purge gasstream. In this particular embodiment, the reformer furnace uses all ofthe PSA purge gas as fuel. Additionally, it uses a novel hydrogen PSAdesign that is lower cost. By virtue of this novel PSA design, the PSApurge gas is sufficient to satisfy all fuel requirements of the reformerfurnace. Because the scheme is self-sufficient in reformer furnace fuelrequirements, there is no requirement of any import of supplementalfuel. By virtue of the novel reformer and the novel PSA designs, thesyngas/flue gas CO2 distribution is higher than the conventional design.

In a still further embodiment of the present invention, the novel steamreformer design is used along with a novel hydrogen PSA design that islower cost. This embodiment is self-sufficient in reformer furnace fuelrequirements and therefore, does not require any import of supplementalfuel. Additionally, a second novel gas separation unit is designed to beincluded in this embodiment (preferably an adsorption based unitalthough a membrane or a cryogenic separation unit may be used) thatseparates the compressed primary PSA unit purge gas into two streams—onethat is recycled back as feed to the reforming section and the otherthat is used as reformer furnace fuel. Steps one to four of thisembodiment are the same with regard to steps one to four above. Thefifth step includes introducing said fourth gas mixture into either astandard recovery or a special low recovery PSA, wherein said fourth gasis separated into a hydrogen enriched stream and a PSA purge gas stream.A second novel gas separation unit is additionally employed, preferablyan adsorption based unit, that separates the compressed primary PSA unitpurge gas into two streams, one that is recycled back as feed to thereforming section and the other that is used as reformer furnace fuel.While an adsorption based unit is preferred, a membrane or a cryogenicseparation unit may also be used. The scheme is self-sufficient inreformer furnace fuel requirements and therefore, does not require anyimport of supplemental fuel. By virtue of the novel reformer, the novelprimary hydrogen PSA, and the novel second adsorption based separationunit, the syngas/flue gas CO2 distribution is higher than theconventional design.

BRIEF DESCRIPTION OF DRAWINGS

The invention may be understood by reference to the followingdescription taken in conjunction with the accompanying drawings, and inwhich:

FIG. 1 is a schematic representation of a conventional SMR basedhydrogen plant with carbon dioxide recovery.

FIG. 2 is a schematic representation of one embodiment of the presentinvention.

FIG. 3 is a schematic representation of another embodiment of thepresent invention.

FIG. 4 is a schematic representation of a still further embodiment ofthe present invention.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention is based on the design of a novel steam reformerunit, a novel hydrogen PSA unit design, a novel hydrogen/nitrogenenrichment unit design, and novel processing scheme application. Theseinnovations result in re-allocating most of the total hydrogen plant CO2emissions load to the high pressure syngas stream, or streams, exitingthe water gas shift reactor while minimizing the CO2 emissions load fromthe reformer furnace flue gas. As compared to the conventional 60/40split of total CO2 emissions in syngas/flue gas streams for steamreformer based conventional hydrogen plant designs, the presentinvention results in 85/15 or better CO2 split. This will permit about85% or better of the total CO2 emissions load to be captured from syngasstream, using the conventional, well proven and cost effective aminescrubbing technology. Such 85% or better CO2 capture is much greaterthan the 55% to 60% maximum possible using conventional steam reformerbased hydrogen plant technology. Since CO2 recovery from high pressuresyngas stream is much easier and cost effective compared to that fromlow pressure reformer furnace flue gases, a major cost benefit forequivalent CO2 recovery results with the present invention.

The described H2 plant design would permit recovery of between about 85%and about 95%+ of the total plant CO2 generation from the high pressuresyngas stream as opposed to the customary 50% to 60%. Current thinkingamong industry experts indicates that such 85% to 95%+ of total CO2recovery is a good practical target leading to achieving goals of“greenhouse gas sequestration”. In such case, it would be of significantvalue to have means of doing so in a cost effective way. Currentconventional H2 plants use steam reformer based technology that permitsonly 50% to 60% of the total CO2 emissions to be recovered costeffectively from the high pressure syngas stream upstream of the PSAunit. The remaining 40% or so ends up in the reformer furnace flue gaswhich is at near atmospheric pressure, having low CO2 concentrations.

CO2 recovery from reformer furnace flue gas is not practicedconventionally. There are processes currently being developed due tointerest in total CO2 capture. Only one or two processes can claimsuccess in CO2 recovery from flue gases on a commercial scale though.Large scale applications using these limited processes have not yet beencommercially established with long term reliable operation. Theprevailing much lower CO2 partial pressure in the flue gas, resultingfrom low CO2 concentration and very low total flue gas pressure, makesit much more difficult to capture CO2. Further, flue gas pressure isvery low, near atmospheric, which will require compression. Large fluegas volumes make this expensive. Further, presence of residual 1 mol %to 3 mol % O2 in flue gas make the application prone to severe equipmentcorrosion and solvent degradation due to oxidation reactions. Inaddition, due to the presence of contaminants such as NOX, SOX,particulates etc., the flue gas requires significant scrubbing andclean-up before it can be processed in the CO2 recovery unit. All ofthese factors make flue gas equipment very expensive and the processvery energy intensive, compared to CO2 recovery for high pressure syngasstream such as the water gas shift reactor effluent.

In comparison, the CO2 recovery from high pressure, higher CO2concentration syngas stream exit the water gas shift unit is mucheasier, conventional and quite a bit less expensive. The high pressureof the syngas stream, coupled with higher CO2 concentration results in amuch higher CO2 partial pressure which makes CO2 removal easy. Nospecial scrubbing or removal of contaminents is required, and the streamcan be used directly in the conventional amine scrubbing unit for CO2recovery. Such CO2 removal from high pressure syngas streams has beenconventionally practiced in industry for more than 20 to 30 years.

Therefore, a process that changes the CO2 split in syngas/flue gas fromconventional 60%/40% to about 95%/5% is very desirable from CO2 recoveryview point.

The present invention has several novel components; these can be appliedeither separately, or in combination, as deemed suitable for givenapplication at hand. The present invention is a method ofre-distributing CO2 balance from reformer furnace flue gas to the highpressure syngas exit water gas shift reaction unit, and then applyingconcepts of gas separation using novel processes.

The conventional SMR based hydrogen plant with carbon dioxide recoveryis illustrated in FIG. 1. It uses a standard steam methane reformer(SMR) technology 103 followed by high temperature water gas shiftreactor 106 to take a hydrocarbon stream 102 and a steam stream 101, andto produce a hydrogen rich syngas stream containing hydrogen, asignificant amount of carbon dioxide, carbon monoxide, methane, nitrogenand other minor impurities. This syngas is cooled in waste heat recoveryequipment 104 to generate steam 105. The syngas is then routed to awater gas shift unit 106, typically a high temperature shift unit, forconversion of carbon monoxide to additional hydrogen by reaction withwater vapor. This syngas is further cooled in waste heat recoveryequipment 107 to generate steam 108. The cooled syngas is purified in acarbon dioxide recovery unit 109, thereby recovering carbon dioxide 110.The ‘sweet’ syngas is then further purified in a pressure swing adsorber(PSA) unit 111 for recovering a relatively pure hydrogen product 112.The residual contents of the syngas stream, after hydrogen productrecovery 113 is used as fuel for the reforming furnace. Typically, thePSA purge gas is not enough to satisfy the total reformer furnace fuelrequirements. The supplemental fuel requirements for the reformerfurnace are provided by import NG or other suitable fuel 119. Thereformer furnace flue gas is cooled in waste heat recovery units 114 togenerate steam 115 and to preheat reformer feed streams. The flue gasalso contains significant amounts of carbon dioxide. Where required ordesired, this carbon dioxide is removed in a special amine wash system116, which produces relatively pure carbon dioxide 117 and residual fluegas 118.

Customary practice has been to not capture any CO2 from reformer furnaceflue gases. In case it is desired to do so, the available currenttechnology for carbon dioxide recovery from flue gas, is based onspecially designed amine based scrubbing system. Such CO2 removalsystems for low pressure flue gas stream is quite different thatcommonly employed for CO2 removal from high pressure syngas streams. Themuch lower carbon dioxide percentage in flue gas, and very low totalpressure of flue gas make it very difficult to capture carbon dioxide.Flue gas CO2 revovey systems are relatively new, and tend to beexpensive due to the flue gas stream containing significant amounts ofwater and between about 1 and about 3 mole % oxygen. The oxygen presencein flue gas tends to corrode the equipment and degrade the solvent. Thelow flue gas pressure and low carbon dioxide concentration results invery low CO2 partial pressure, which requires physically largerequipment, and the capture requires a very reactive solvent. Thepresence of moisture and carbon dioxide typically pose corrosion issuesas well. The utility and energy requirements are significantly greateras compared to that for conventional, CO2 recovery systems from highpressure syngas stream.

In comparison, the carbon dioxide recovery from the high pressure syngasstream is much easier, without severe corrosion issues, and is much lessexpensive. Utility and energy requirements are significantly lower ascompared to the flue gas CO2 recovery systems.

Therefore, it is very desirable and cost effective to have a hydrogenplant design that allows 85% to 95%+ carbon dioxide recovery from syngasstream alone,.

The present invention would permit recovery of between about 85% andabout 95% of the total plant carbon dioxide generation from a highpressure syngas stream, as opposed to the customary 50% to 60%. Withthis in mind, it is desirable to design an SMR (primary reformer) basedprocess that contains between about 85% and about 95% (as opposed to theconventional art 50 to 60%) of total carbon dioxide in the high pressuresyngas stream. The novel scheme will permit reasonable CO2 recovery (85%to 95%) from syngas stream alone, thereby not requiring any further CO2recovery from flue gas. The instant invention describes processconfigurations, and operating conditions, which allow one to achievethese objectives:

Turning now to FIG. 2 which illustrates one embodiment of the presentinvention, hydrocarbon stream 202 and steam stream 201 are introduced topre-reformer followed by a novel primary reformer, or simply a novelprimary reformer 203, wherein a syngas stream 251 comprising at leastcarbon dioxide and hydrogen is produced. The reformer furnace flue gasis cooled in waste heat recovery units 214 to generate steam 215, topreheat reformer feed streams, and residual flue gas 218 Syngas stream251 is sent to a waste heat recovery unit 204 to recover steam 205. Theexit of waste heat recovery, stream 252 is then introduced to a hightemperature shift reactor followed by a low temperature shift reactor,or alternatively either an isothermal or a medium temperature shiftreactor (symbolically represented by 206). This produces a carbondioxide richer stream 253. Carbon dioxide richer stream 253 is furthercooled in waste heat recovery unit 207 to generate steam 208, and acooler syngas stream 254. Stream 254 is introduced into a CO2 recoveryunit 209 to recover enriched CO2 stream 210 and sweet syngas stream 255.The sweet syngas stream goes to a conventional PSA unit 211, whereinrelatively pure hydrogen 212 is recovered, and residual stream 213 issent to the primary reformer furnace as fuel. Additional supplementalfuel 219 is added to the reformer furnace as required.

Another aspect of the present invention includes the design of a novelPSA unit for H2 recovery from syngas. When this is used in conjunctionwith the novel steam reformer, a process results (shown in FIG. 3).

Turning now to FIG. 3 which illustrates another embodiment of thepresent invention, hydrocarbon stream 302 and steam stream 301 areintroduced to pre-reformer followed by a novel primary reformer, orsimply a novel primary reformer 303, wherein a syngas stream 351comprising at least carbon dioxide and hydrogen is produced. Thereformer furnace flue gas is cooled in waste heat recovery units 314 togenerate steam 315, to preheat reformer feed streams, and residual fluegas 318 Syngas stream 351 is sent to a waste heat recovery unit 304 torecover steam 305. The exit of waster heat recovery stream 352 is thenintroduced to a high temperature shift reactor followed by a lowtemperature shift reactor, or alternatively either an isothermal or amedium temperature shift reactor (symbolically represented by 306). Thisproduces a carbon dioxide richer stream 353. Carbon dioxide richerstream 353 is further cooled in waste heat recovery unit 307 to generatesteam 308, and a cooler syngas stream 354. Stream 354 is introduced intoa CO2 recovery unit 309 to recover enriched CO2 stream 310 and sweetsyngas stream 355. The sweet syngas stream goes to a novel PSA unit 311that has intentionally designed low H2 recovery and is lower in costthan conventional, wherein relatively pure hydrogen 312 is recovered,and residual stream 313 is sent to the primary reformer furnace as fuel.Additional supplemental fuel is not required.

Another aspect of the invention includes the design of a novel PSA unitfor H2 recovery from syngas. When this is used in conjunction with thenovel steam reformer, a process results (shown in FIG. 4).

Turning now to FIG. 4 which illustrates another embodiment of thepresent invention, hydrocarbon stream 402 and steam stream 401 areintroduced to pre-reformer followed by a novel primary reformer, orsimply a novel primary reformer 403, wherein a syngas stream 451comprising at least carbon dioxide and hydrogen is produced. Syngasstream 451 is sent to a waste heat recovery unit 404 to recover steam405. The exit of waster heat recovery stream 452 is then introduced to ahigh temperature shift reactor followed by a low temperature shiftreactor, or alternatively either an isothermal or a medium temperatureshift reactor (symbolically represented by 406). This produces a carbondioxide richer stream 453. Carbon dioxide richer stream 453 is furthercooled in waste heat recovery unit 407 to generate steam 408, and acooler syngas stream 454. Stream 454 is introduced into a CO2 recoveryunit 409 to recover enriched CO2 stream 410 and sweet syngas stream 455.The sweet syngas stream 455 goes to a novel PSA unit 411 that has beenintentionally designed for low H2 recovery and is lower in cost thanconventional designs, wherein relatively pure hydrogen 412 is recovered.In some variations, the PSA unit 411 can be a conventional unit withconventional H2 recovery to save costs of tail gas 413 compression. Theresidual tail gas stream 413 is compressed in unit 420 to obtaincompressed tail gas stream 456 which is sent to another novel gasseparation unit 421 (adsorption based preferred, but a membrane or acryogenic unit may also be used) where the tail gas stream is separatedinto two streams: one enriched in nitrogen and hydrogen, and the otherenriched in hydrocarbons. The hydrogen and nitrogen enriched stream willhave at least 40% of the total nitrogen present in the feed to the unit,along with at least 90% of the hydrogen present in the feed to the unit.The hydrogen/nitrogen rich stream 422 is sent to the primary reformerfurnace 403 as fuel and the other hydrocarbon rich stream 423 iscompressed in unit 424 to form?? stream 457. Stream 457 is recycled tothe reformer area as partial feed. Additional supplemental fuel is notrequired.

It will be recognized that the novel steam reformer, the novel H2 PSA,and the separation of the PSA purge gas using a novel process are novelprocess unit designs of this invention, with specific operatingconditions of, at least, temperature, pressure, and composition, andconcept and/or application in some cases, which are novel; all otherunits by themselves are conventional.

The following examples illustrate some details and benefits of thepresent invention.

Note, as used herein, the term “steam to carbon ratio” is understood tohave units of Lb-mole steam/Lb-atoms of carbon.

Base Case (FIG. 1): Conventional Hydrogen Plant Design

-   -   Supplemental hydrocarbon fuel required    -   Low temperature shift not used    -   Standard reformer process and furnace conditions (size=100%        base)    -   Standard PSA design and recovery    -   Standard steam to carbon ratio    -   100 to 120 MMSCFD hydrogen product flow    -   About 57% of total carbon dioxide recovered from syngas    -   Carbon dioxide released to the atmosphere from flue gas (43% of        total)    -   No flue gas CO2 recovery practiced.    -   Plant efficiency at 100% base.

EXAMPLE 1 FIG. 2

-   -   Supplemental hydrocarbon fuel not required    -   Low temperature shift used    -   Novel reformer process and furnace conditions (size=same as        base)    -   Standard PSA design and recovery    -   Novel steam to carbon ratio    -   Hydrogen product flow (100% of base)    -   Carbon dioxide recovered from syngas (67% of total)    -   Carbon dioxide released to the atmosphere from flue gas (33% of        total)    -   No flue gas carbon dioxide recovery employed    -   Plant efficiency (marginally better than base)

EXAMPLE 2 FIG. 3

-   -   Supplemental hydrocarbon fuel not required    -   Low temperature shift used    -   Novel reformer process and furnace conditions (size=100% base)    -   Novel PSA design and recovery (less beds used, less expensive        than base)    -   Novel steam to carbon ratio    -   Hydrogen product flow (70% of base)    -   Carbon dioxide recovered from syngas (89% of total)    -   Carbon dioxide released to the atmosphere from flue gas (11% of        total)    -   No flue gas carbon dioxide recovery required    -   Plant energy within 8% of base.

EXAMPLE 3 FIG. 3

-   -   Supplemental hydrocarbon fuel not required    -   Low temperature shift used    -   Novel reformer process and furnace conditions (size=133% base)    -   Novel PSA design and recovery (less beds used, less expensive        than base)    -   Novel steam to carbon ratio    -   Hydrogen product flow (100% of base)    -   Carbon dioxide recovered from syngas (90% of total)    -   Carbon dioxide released to the atmosphere from flue gas (10% of        total)    -   No flue gas carbon dioxide recovery required    -   Plant energy within 7% of base.

EXAMPLE 4 FIG. 4

-   -   Supplemental hydrocarbon fuel not required    -   Low temperature shift used    -   Novel reformer process and furnace conditions (size=100% base)    -   Novel PSA design and recovery (less beds used, less expensive        than base)    -   Novel steam to carbon ratio    -   Hydrogen product flow (69% of base)    -   Carbon dioxide recovered from syngas (>98% of total)    -   Carbon dioxide released to the atmosphere from flue gas (<2% of        total)    -   Novel tail gas separation unit employed for recycle to reformer        feed    -   No flue gas carbon dioxide recovery required    -   Plant energy within 12% of base.

EXAMPLE 5 FIG. 4

-   -   Supplemental hydrocarbon fuel not required    -   Low temperature shift used    -   Novel reformer process and furnace conditions (size=133% base)    -   Novel PSA design and recovery (less beds used, less expensive        than base)    -   Novel steam to carbon ratio    -   Hydrogen product flow (100% of base)    -   Carbon dioxide recovered from syngas (>98% of total)    -   Carbon dioxide released to the atmosphere from flue gas (<2% of        total)    -   Novel tail gas separation unit employed for recycle to reformer        feed    -   No flue gas carbon dioxide recovery required    -   Plant energy within 9% of base.

In another embodiment of the present invention the primary reformer tubeexit temperatures is between about 1700° F. (927° C.) and about 1750° F.(954° C.), preferably about 1730° F. (943° C.). This is in contrast withthe conventional primary reformer tube exit temperature of between about160° F. (871° C.) and about 1650° F. (899° C.).

In another embodiment of the present invention, the primary reformerfurnace bridge wall temperatures is between about 1850° F. (1010° C.)and 1950° F. (1066° C.), preferably about 1900° F. (1038° C.). This isin contrast with the conventional primary reformer furnace bridge walltemperatures of between about 1950° F. (1066° C.) and about 2050° F.(1121° C.). The temperature difference at the reformer furnace bridgewall, is herein defined as the bridge wall temperature minus the primaryreformer tube exit temperature.

In a still further embodiment, a carbon ratio of between about 3.0 and4.0, preferably about 3.2, is used. This is in contrast to theconventional value of about 2.8.

In yet another embodiment, other process conditions such as pressure,temperature and composition are adjusted as necessary in order toachieve no more than about 1 mol % (preferably less than about 0.5%) drycarbon monoxide slip and about 2 mol % (preferably less than about 0.5%)dry methane slip in the syngas stream at the inlet to the PSA, both ondry mol % basis.

In another embodiment, a low recovery PSA is used to recover only anamount of hydrogen that leaves enough un-recovered PSA purge gas streamsufficient to satisfy total supplemental fuel requirements of thereformer furnace. This low recovery PSA has a hydrogen recovery ofbetween about 50% and about 65%, in contrast with the conventionalsystem which has a hydrogen recovery of about 87%. The use of a lowrecovery PSA will preclude the need for any external hydrocarbon basedsupplemental fuel requirement. The use of such low recovery PSA designswill permit the use of less adsorption beds, typically between 4 and 10,preferably between 5 and 9, more preferably between 6 and 8, and stillmore preferably between 4 and 5. This is contrasted with the 10 to 14beds typically required for a hydrogen plant with 100 to 120 MMSCFD(28,316 to 33,979 NCMD at 16° C.) hydrogen product capacity.

In still another embodiment, the PSA hydrogen recovery is adjusted sothat the purge fuel gas from the PSA flow is sufficient for all fueldemands in the primary reformer furnace. No additional supplemental fuelis used.

In yet still another embodiment, the primary reformer furnace excess airis adjusted in order to achieve a stable flame with essentially all ofthe hydrogen containing fuel, while establishing a reasonable limit onadiabatic flame temperature (typically less than about 4000° F., 2204°C.).

In another embodiment, at least about 99% of the available carbondioxide is recovered from a high pressure syngas stream upstream of PSAusing a conventional technology such as, but not limited to, aMDEA, thatare well proven and cost effective from capital and energy requirementsview point. Any appropriate conventional technology known to the skilledartisan is appropriate.

In another embodiment, the novel PSA design permits higher than 1.2 Bara(17.4 psia) PSA purge gas pressure (typically between about 5 Bara andabout 10 Bara, or about 72.5 psia and about 145 psia) due to the reducedrecovery needs. The higher pressure helps minimize the size and cost ofthe associated compressor upstream of either an associated noveladsorption unit, a membrane unit or a cold box unit for further tail gasseparation.

In another embodiment, a novel stand alone adsorption based gasseparation unit is included for separation of the PSA (conventional ornovel hydrogen PSA design down stream of syngas CO2 removal unit). Thisnovel unit separates the PSA tail gas (purge gas) post compression, intotwo gas streams: one rich in H2 and N2, and the other rich inhydrocarbons. The H2/N2 rich stream is used as fuel in the reformerfurnace; the hydrocarbon rich stream is compressed and recycled back tothe reformer as feed.

In another embodiment, the membrane system may be operated at suitablepressures by further compressing the PSA purge gas (that exits the PSAunit at between about 5 Bara and about 10 Bara (about 72.5 psia andabout 145 psia) such that the residue hydrocarbon stream exiting themembrane unit can be recycled back as part feed to the reformer withoutfurther compression. The membrane permeate stream will be used as fuelin the reformer furnace. No additional supplemental fuel will need to beimported.

In another embodiment, where the cold box/membrane system is employed onnovel PSA tail gas (at 5 to 10 Bara pressure, about 72.5 psia and about145 psia), an aMDEA unit, for syngas CO2 recovery is not required, asthe cold box unit recovers carbon dioxide from the PSA purge gas (aftercompression) in a cold box type cryogenic carbon dioxide separationunit. The remaining stream from the cold box is processed in a membraneunit to recover two separate streams; a raw hydrogen stream at lowpressure (but greater than about 1.2 Bara, 17.4 psia) to be used asreformer fuel, and a second stream containing remaining hydrocarbons.This hydrocarbon stream is compressed as required, and recycled back tothe reformer as part feed. A flue gas carbon dioxide recovery system isnot required.

In another embodiment, at least about 99% of the available carbondioxide is recovered from a high pressure syngas stream upstream of PSAusing a conventional technology such as, but not limited to, aMDEA or acold box/membrane unit that are well proven and cost effective fromcapital and energy requirements view point. Any appropriate conventionaltechnology known to the skilled artisan is appropriate.

Other embodiments may comprise additional units such as a syngas carbondioxide recovery unit and/or a membrane purification unit. Otherembodiments may comprise additional units such as a combined cold boxand/or a membrane purification unit. These additional units may be usedin any combination recognized as plausible by the skilled artisan.

Illustrative embodiments have been described above. While the method inthe present application is susceptible to various modifications andalternative forms, specific embodiments thereof have been shown by wayof example in the drawings, and have been herein described in detail. Itshould be understood, however, that the description herein of specificembodiments is not intended to limit the method in the presentapplication to the particular forms disclosed, but on the contrary, themethod in the present application is to cover all modifications,equivalents, and alternatives falling within the spirit and scope of themethod in the present application, as defined by the appended claims.

It will, of course, be appreciated that in the development of any suchactual embodiment, numerous implementation-specific decisions must bemade to achieve the developer's specific goals, such as compliance withsystem-related and business-related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time-consuming, but,would nevertheless, be a routine undertaking for those of ordinary skillin the art, having the benefit of this disclosure.

1. A method of re-distributing the CO2 balance from a reformer furnaceflue gas to the high pressure syngas exit water gas shift reaction unit,comprising; providing a first gas mixture; introducing said first gasmixture either into a pre-reformer followed by a primary reformer, ordirectly into a primary reformer, thereby generating a second gasmixture comprising hydrogen, carbon monoxide, carbon dioxide;introducing said second gas mixture into at least one isothermal shiftreactor, or a combination of high followed by a low temperature shiftreactor, or a medium temperature shift reactor, thereby generating athird gas mixture; introducing said third gas mixture into an aminewash, wherein said third gas is separated into a fourth gas mixture anda carbon dioxide enriched stream; introducing said fourth gas mixtureinto a standard H2 PSA unit, wherein said fourth gas is separated into ahydrogen enriched stream and a PSA purge gas stream; introducing saidPSA purge gas stream as fuel into the reformer furnace along withnatural gas, a portion of the feed hydrocarbon stream, or any otherexternal supplemental fuel for the reformer furnace.
 2. The method ofclaim 1, wherein said steam reformer has a tube exit temperature betweenabout 1700° F. and about 1750° F.
 3. The method of claim 2, wherein saidtube exit temperature is about 1730° F.
 4. The method of claim 1,wherein said steam reformer has a furnace bridge wall temperature ofbetween about 1850° F. and about 1950° F.
 5. The method of claim 4,wherein said furnace bridge wall temperature is about 1900° F.
 6. Themethod of claim 1, wherein said steam reformer has a steam to carbonratio of between about 3.0 and about 4.0.
 7. The method of claim 6,wherein said steam to carbon ratio is about 2.8.
 8. The method of claim1, wherein the excess air to the furnace of said primary reformer isadjusted in order to achieve a stable flame while maintaining anadiabatic flame temperature of about 4000° F.
 9. The method of claim 1,wherein at least about 99% of the carbon dioxide present in the fourthgas stream is removed by said amine wash system.
 10. A method ofre-distributing CO2 balance from reformer furnace flue gas to the highpressure syngas exit water gas shift reaction unit, comprising;providing a first gas mixture; introducing said first gas mixture into apre-reformer followed by a primary reformer, or directly into a primaryreformer, thereby generating a second gas mixture comprising hydrogen,carbon monoxide, carbon dioxide; introducing said second gas mixtureinto at least one isothermal shift reactor, or a combination of highfollowed by a low temperature shift reactor, or a medium temperatureshift reactor, thereby generating a third gas mixture; introducing saidthird gas mixture into an amine wash, wherein said third gas isseparated into a fourth gas mixture and a carbon dioxide enrichedstream; introducing said fourth gas mixture into special low recoveryPSA, wherein said fourth gas is separated into a hydrogen enrichedstream and a PSA purge gas stream; introducing said purge gas from novelPSA to the reformer furnace as fuel; wherein no additional supplementalfuel is sent to the reformer furnace.
 11. The method of claim 10,wherein said novel PSA has a hydrogen recovery between about 50% andabout 65%.
 12. The method of claim 10, wherein said PSA has reducednumber of adsorption beds compared to similar size conventional units.13. The method of claim 12, wherein the number of adsorption beds isbetween 8 and
 10. 14. The method of claim 10, wherein the hydrogenrecovery of said PSA is adjusted such that the PSA purge gas stream heatcontent as fuel is sufficient to satisfy the fuel demand of the primaryreformer.
 15. The method of claim 10 wherein the novel PSA unit deliversa sufficient quantity of fuel by varying the hydrogen % recovery withinthe novel PSA unit such that no additional supplemental fuel to thereformer furnace is required.
 16. The method of claim 10, wherein saidpurge gas stream has a pressure of between about 5 bara and about 10bara.
 17. The method of claim 10, wherein said purge gas stream has apressure of greater than about 1.2 bara.
 18. A method of separatingcarbon dioxide from a gas mixture, comprising; providing a first gasmixture; introducing said first gas mixture either into a pre-reformerfollowed by a primary reformer, or directly into a primary reformer,thereby generating a second gas mixture comprising hydrogen, carbonmonoxide, carbon dioxide introducing said second gas mixture into atleast one isothermal shift reactor, or a combination of high followed bya low temperature shift reactor, or a medium temperature shift reactor,thereby generating a third gas mixture; introducing said third gasmixture into an amine wash, wherein said third gas is separated into afourth gas mixture and a carbon dioxide enriched stream; introducingsaid fourth gas mixture into either a standard recovery or a special lowrecovery PSA, wherein said fourth gas is separated into a hydrogenenriched stream and a PSA purge gas stream; compressing said PSA purgegas stream to a suitable pressure; introducing said compressed purge gasstream to a novel gas separation unit selected from an adsorption basedunit, a membrane separation unit or a cryogenic separation unit, thatseparates the compressed PSA unit purge gas into two streams, a hydrogenand nitrogen enriched stream and a stream of residual gases; introducingthe hydrogen and nitrogen enriched stream to the reformer furnace asfuel and recycling the stream of residual gases back to the reformer aspartial feed after compression as required; wherein no additionalsupplemental fuel is sent to the reformer furnace.
 19. The method ofclaim 18, wherein said novel gas separation unit is a novel adsorptionbased unit.
 20. The method of claim 19, wherein the said adsorptionbased unit can be of 4 to 5 adsorption beds.
 21. The method of claim 19,wherein said hydrogen and nitrogen enriched stream will have at least40% of the total nitrogen present in the feed to the unit, along with atleast 90% of the hydrogen present in the feed to the unit.
 22. Themethod of claim 18, wherein said residue gas stream from the novel gasseparation unit is compressed to a suitable pressure.
 23. The method ofclaim 22, wherein said high pressure residue hydrocarbon stream isrecycled as part feed to the reformer.
 24. The method of claim 18,wherein said novel gas separation unit is either a cryogenic process (doyou mean separation unit?) or a membrane based process (do you meanseparation unit??).